The present invention relates to reverse cementing operations useful in subterranean formations, and more particularly, to the use of ball operated back pressure valves in reverse circulation operations.

After a well for the production of oil and/or gas has been drilled, casing may be run into the wellbore and cemented. In conventional cementing operations, a cement composition is displaced down the inner diameter of the casing. The cement composition is displaced downwardly into the casing until it exits the bottom of the casing into the annular space between the outer diameter of the casing and the wellbore. It is then pumped up the annulus until a desired portion of the annulus is filled.

The casing may also be cemented into a wellbore by utilizing what is known as a reverse-cementing method. The reverse-cementing method comprises displacing a cement composition into the annulus at the surface. As the cement is pumped down the annulus, drilling fluids ahead of the cement composition around the lower end of the casing string are displaced up the inner diameter of the casing string and out at the surface. The fluids ahead of the cement composition may also be displaced upwardly through a work string that has been run into the inner diameter of the casing string and sealed off at its lower end. Because the work string by definition has a smaller inner diameter, fluid velocities in a work string configuration may be higher and may more efficiently transfer the cuttings washed out of the annulus during cementing operations.

The reverse circulation cementing process, as opposed to the conventional method, may provide a number of advantages. For example, cementing pressures may be much lower than those experienced with conventional methods. Cement composition introduced in the annulus falls down the annulus so as to produce little or no pressure on the formation. Fluids in the wellbore ahead of the cement composition may be bled off through the casing at the surface. When the reverse-circulating method is used, less fluid may be handled at the surface and cement retarders may be utilized more efficiently.

In reverse circulation methods, it may be desirable to stop the flow of the cement composition when the leading edge of the cement composition slurry is at or just inside the casing shoe. In order to determine when to cease the reverse circulation fluid flow, the leading edge of the slurry is typically monitored to determine when it arrives at the casing shoe. Logging tools and tagged fluids (by density and/or radioactive sources) have been used monitor the position of the leading edge of the cement slurry. If a significant volume of the cement slurry enters the casing shoe, clean-out operations may need to be conducted to ensure that cement inside the casing has not covered targeted production zones. Position information provided by tagged fluids is typically available to the operator only after a considerable delay. Thus, even with tagged fluids, the operator is unable to stop the flow of the cement slurry into the casing through the casing shoe until a significant volume of cement has entered the casing. Imprecise monitoring of the position of the leading edge of the cement slurry can result in a column of cement in the casing 100 feet to 500 feet long. This unwanted cement may then be drilled out of the casing at a significant cost.

The present invention relates to reverse cementing operations useful in subterranean formations, and more particularly, to the use of ball operated back pressure valves in reverse circulation operations.

According to one aspect of the invention, there is provided a method for selectively closing a downhole one way check valve, the method having the following steps: attaching the valve to a casing; locking the valve in an open configuration; running the casing and the valve into the wellbore; reverse circulating a composition down an annulus defined between the casing and the wellbore; injecting a plurality of balls into the annulus; unlocking the valve with the plurality of balls; and closing the valve.

A further aspect of the invention provides a valve having a variety of components including: a plug removably connected to a housing; a plug seat; and a baffle having a plurality of holes. When the plug is connected to the housing, the valve is in an open position, and fluid may flow through the valve. When the holes in the baffle become plugged, the plug becomes disconnected from the housing and moves into the plug seat, restricting flow through the valve. Another aspect of the invention provides a system for reverse-circulation cementing a casing in a wellbore, wherein the system has a valve and a plurality of balls. The valve may have a plug removably connected to a housing, a plug seat, and a baffle having a plurality of holes. The plug may be connected to the housing, the valve may be in an open position, and fluid may flow through the valve. When the holes in the baffle become plugged, the plug may become disconnected from the housing and move into the plug seat, restricting flow through the valve. The balls may be sized to cause the holes in the baffle to become plugged.

The objects, features, and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the following description of the preferred embodiments.

It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, as the invention may admit to other equally effective embodiments.

The present invention relates to reverse cementing operations useful in subterranean formations, and more particularly, to the use of ball operated back pressure valves in reverse circulation operations.

FIG. 1A illustrates a cross-sectional side view of a valve 1. This embodiment of the valve 1 has a plug seat 2, which is a cylindrical structure positioned within the inner diameter of a sleeve 3. A seal 4 closes the interface between the outer diameter of the plug seat 2 and the inner diameter of the sleeve 3. The seal 4 may be an O-ring seal, Halliburton Weld A™ Thread-Locking Compound, or any other seal. The plug seat 2 has an inner bore 5 for passing fluid through the plug seat 2. At the mouth of the inner bore 5, the plug seat 2 has a conical lip 6 for receiving a plug 7 when the valve is in a closed position.

The valve 1 also has a housing 8 that suspends the plug 7 outside the plug seat 2. The housing 8 has a baffle section 9 (shown more clearly in FIG. 1B). In the illustrated embodiment, the plug 7 has a cylindrical structure having an outside diameter larger than an inside diameter of the inner bore 5 of the plug seat 2, but slightly smaller than an inside diameter of an inner wall 10 of the housing 8. This leaves a flow conduit 11 extending between an outer wall 12 of the housing 8 and the inner wall 10, which abuts the plug 7.

When the plug 7 is suspended outside the plug seat 2 of the valve 1, as illustrated in FIG. 1A, the valve 1 is locked in an open configuration. The plug 7 may be suspended outside the plug seat 2 by a shear pin or pins 13, which may connect the plug 7 to the inner wall 10 of the housing 8.

Referring now to FIG. 1B, the flow conduit 11 extends through the housing 8, between the inner wall 10 and the outer wall 12. The baffle section 9 is an opening to the flow conduit 11. The baffle section 9 has a plurality of holes 14. The holes 14 may have a radial pattern around the baffle section 9. The holes 14 and the flow conduit 11 allow for fluid passage around the plug 7.

FIGS. 2A and 2B illustrate cross-sectional side views of a valve similar to that illustrated in FIG. 1A, wherein FIG. 2A shows the valve in a locked, open configuration and FIG. 2B shows the valve in an unlocked, closed configuration. In FIG. 2A, the plug 7 is suspended outside of the plug seat 2 to hold the valve 1 in an open position. Pins 13 retain the plug 7 outside of the plug seat 2. In FIG. 2B, the plug 7 is seated in the plug seat 2, within the conical lip 6 of the plug seat 2 to close the valve 1.

An example of a reverse cementing process of the present invention is described with reference to FIGS. 2A and 2B. The valve 1 is run into the wellbore in the configuration shown in FIG. 2A. With the plug 7 held outside of the plug seat 2, such that the valve 1 is in an open position, fluid from the wellbore is allowed to flow freely up through the valve 1, wherein it passes through the holes 14 of the baffle section 9 and through the flow conduit 11 of the housing 8. As casing 26 is run into the wellbore, the wellbore fluids flow through the open valve 1 to fill the inner diameter of the casing 26 above the valve 1. After the casing 26 is run into the wellbore to its target depth, a cement operation may be performed on the wellbore. In particular, a cement composition slurry may be pumped in the reverse-circulation direction, down the annulus defined between the casing 26 and the wellbore. Returns from the inner diameter of the casing 26 may be taken at the surface. The wellbore fluid enters the sleeve 3 at its lower end below the valve 1 illustrated in 3A and flows up through the valve 1 as the cement composition flows down the annulus.

Balls 15 may be used to close the valve 1, when a leading edge 16 of cement composition 17 reaches the valve 1. Balls 15 may be inserted ahead of the cement composition 17 when the cement composition is injected into the annulus at the surface. These balls 15 may be located in a fluid that is just ahead of the cement, or even at the leading edge 16 of the cement. The balls 15 flow down the annulus, around the bottom of the casing 26, and back up into the valve 1 to close it. As shown in FIG. 2A, the balls 15 may be pumped at the leading edge 16 of the cement composition 17 until the leading edge 16 passes through the flow conduit 11 of the housing 8 of the valve 1. When the leading edge 16 of the cement composition 17 passes through baffle section 9 of the housing 8, the balls 15 seat and seal off in the holes 14, preventing any further flow through the holes 14. At this point, hydrostatic pressure from the column of cement begins to build up underneath the housing 8. This pressure works across an O-ring 18 on the outer diameter of the plug 7. As the differential pressure created between the cement and lighter fluid above the valve 1 increases, the pins 13 may shear, allowing the plug 7 to shift upward into the plug seat 2 so that the plug 7 extends into the conical lip 6. The shear pins 13 may shear at any predetermined shear value. The shear value may change from one application to the next. If the predetermined shear value is low enough, the shear pins 13 may shear without a complete seal between the balls 15 and the holes 14. In fact, when desired, the shear pins 13 may shear when only a portion of the holes 14 are occupied by balls 15. In the instances where the shear pins 13 shear without a complete seal, the back pressure buildup created by the reduced flow of some balls 15 may create the pressure necessary to shear the pins 13. The end of the plug 7 contains a seal 19 that seals inside the plug seat 2. This seal 19 is a back up seal to the balls 15 that are sealing flow through the holes 14 in the event the balls 15 do not create a complete positive seal.

The plug seat 2 and the housing 8 may be attached to a sleeve 3 that will make-up into the casing 26 as an integral part of the casing 26. This allows for casing 26 to be attached below it. The plug seat 2, the housing 8, and the plug 7 may be made of drillable material such as aluminum to facilitate drilling out these components with a roller-cone rock bit if required.

FIG. 2B illustrates a configuration of the valve 1 after the plug 7 has been pumped into the plug seat 2. The plug 7 then prevents flow through the inner bore 5 of the valve 1, effectively closing the valve 1. The closed valve 1 prevents the cement composition 17 from flowing up through the valve 1 into the inner diameter of the casing 26 above the valve 1. The plug 7 may be locked in place using a locking ring 27 (shown only in FIG. 2B) or any other locking device. This allows the valve 1 to be locked in a closed position with or without the presence of continued pressure. Once the valve 1 is closed, casing head pressure can be removed from the well. However, the locking ring 27 or other locking device may not be necessary to maintain the plug 7 in position. The valve 1 will remain in a closed position so long as adequate pressure is maintained.

Referring to FIGS. 3A and 3B, an alternate embodiment is shown. This embodiment allows the valve 1 to be screwed between two joints of casing as an insert. To do so, a valve seat 20 with a casing thread on the outer diameter may be provided. This would allow the valve 1 to be screwed into a casing collar. The thread may be coated with Halliburton Weld A™ Thread-Locking Compound to create a seal around the valve seat 20.

The valve 1 may accept a cementing plug 21 in the upper end of the plug seat 2. The cementing plug 21 is illustrated in FIGS. 4A and 4B. This allows for cementing the casing in place by conventional cementing operations, where the cement is pumped down the inside of the casing and back up the wellbore-to-casing annulus. While a latch-down cementing plug is illustrated, the cementing plug 21 may be a standard cementing plug that lands and seals on top of the valve 1, as illustrated in FIGS. 5A and 5B.

Referring to FIG. 6, a cross-sectional side view of a valve similar to that illustrated in FIGS. 2A and 2B is illustrated. The valve 1 and casing 26 are shown in a wellbore 22, wherein an annulus 23 is defined between the casing 26 and the wellbore 22. In this embodiment, a standard cementing plug or a latch-down plug is run into the inner diameter of the casing 26 to a position immediately above the valve 1. The valve 1 can be secured to the bottom joint of casing as a guide shoe or located above the bottom of the casing 26 similar to where a float collar would be located.

FIGS. 7A and 7B illustrate cross-sectional, side views of a portion of the baffle section 9 of the plug 7. In particular, a hole 14 is shown extending through the baffle section 9. In this embodiment, the hole 14 is cylindrical. In FIG. 7A, the illustrated ball 15 is a sphere having an outside diameter slightly larger than the diameter of the hole 14. The ball 15 plugs the hole 14 when a portion of the ball 15 is pushed into the hole 14 as fluid flows through the hole 14. In FIG. 7B, the illustrated ball 15 is an ellipsoid wherein the greatest outside circular diameter is slightly larger than the diameter of the hole 14. The ellipsoidal ball 15 plugs the hole 14 when a portion of the ball 15 is pushed into the hole 14 as fluid flows through the hole 14.

FIGS. 8A and 8B illustrate cross-sectional, side views of a portion of the baffle section 9 of the plug 7. In particular, a hole 14 is shown extending through the baffle section 9. In this embodiment, the hole 14 is conical. In FIG. 8A, the illustrated ball 15 is a sphere having an outside diameter slightly smaller than the diameter of the conical hole 14 at an exterior surface 24 of the baffle section 9 and slightly larger than the diameter of the conical hole 14 at an interior surface 25 of the baffle section 9. The spherical ball 15 plugs the hole 14 when at least a portion of the ball 15 is pushed into the hole 14 as fluid flows through the hole 14. In FIG. 8B, the illustrated ball 15 is an ellipsoid wherein the greatest outside circular diameter is slightly smaller than the diameter of the conical hole 14 at the exterior surface 24 of the baffle section 9 and slightly larger than the diameter of the conical hole 14 at the interior surface 25 of the baffle section 9. The ellipsoidal ball 15 plugs the conical hole 14 when at least a portion of the ball 15 is pushed into the hole 14 as fluid flows through the hole 14.

In one embodiment of the invention, the valve 1 is made, at least in part, of the same material as the sleeve 3. Alternative materials, such as steel, composites, cast-iron, plastic, cement, and aluminum, also may be used for the valve so long as the construction is rugged to endure the run-in procedure and environmental conditions of the wellbore.

According to one embodiment of the invention, the balls 15 may have an outside diameter of approximately 0.75 inches so that the balls 15 may clear the annular clearance of the casing collar and wellbore (e.g., 7.875 inches×6.05 inches). The composition of the balls 15 may be of sufficient structural integrity so that downhole pressures and temperatures do not cause the balls 15 to deform and pass through the holes 14. The balls 15 may be constructed of plastic, rubber, phenolic, steel, neoprene plastics, rubber coated steel, rubber coated nylon, or any other material known to persons of skill in the art.

The present invention does not require that pressure be applied to the casing to deactivate the valve to the closed position after completion of reverse cementing. There may be instances when pumping equipment may not be able to lift the weight of the cement in order to operate a pressure operated float collar or float shoe.

Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee.